The present invention relates to coarse-foamed fracturing fluids and methods of using such fluids in subterranean fracturing operations.
The term “coarse foamed” as used herein refers to the texture of the foam. A coarse foamed fluid has a relatively nonuniform bubble size distribution (e.g., a combination of large and small gas bubbles) whereas a fine texture foam has relatively uniform bubble size distribution and most of the bubbles are relatively small. (See FIG. 1 illustrating a coarse foam and a fine textured foam at nonlimiting examples of certain quality levels.) The term “quality” as used herein refers to a foam quality level above which a pure fine textured foam exists, which will depend, inter alia, on the particular fluid composition and the foaming agent used. On a schematic plot of viscosity versus quality in a foamed fluid, the foam transition point is the point at which the foamed fluid becomes a more coarse textured foamed fluid. The transition point is a level of maximum viscosity, which may be relatively well-defined in some instances. The foam transition point for a particular foam may vary as a result of, inter alia, the foam composition (e.g., whether it is an aqueous-based foamed fluid or an oil-based foamed fluid). The particular quality level of the foam at the transition point will similarly vary. The coarse-foamed fracturing fluids of the present invention are foamed fluids that have a quality level at or above the foam transition point for the particular fluid.
Hydraulic fracturing is a process commonly used to increase the flow of desirable fluids from a portion of a subterranean formation. Traditional hydraulic fracturing operations usually comprise the steps of placing a viscous fracturing fluid (often an aqueous gelled fluid) into a portion of a subterranean formation at a rate and pressure such that fractures are created or enhanced in a portion of the subterranean formation. The fractures propagate, e.g., as vertical and/or horizontal cracks radially outward from the well bore. In such treatments, once the hydraulic pressure is released, usually the fractures will not remain fully open. Often, particulate materials, known as proppant, are suspended in the fracturing fluid during at least a portion of the fracturing operation. The particulates are carried into the fractures and deposited therein such that when the hydraulic pressure is released the particulates help prevent the fracture from fully closing, and thus, aid in forming conductive channels through which produced fluids may flow into the well bore. Without the particulate material, the fractures tend to close, thus potentially negating any permeability gained by the fracturing operation. Suitable particulate materials must have sufficient compressive strength to resist crushing, but also should be sufficiently non-abrasive and non-angular to preclude cutting and imbedding into the formation.
Conventional fracturing operations are not universally acceptable treatments for all subterranean formations. One factor that may limit the universal application of a conventional fracturing operation is that they tend to leave behind a residue on the surfaces within the formation and the created fractures. This residue may act as a barrier to desirable fluids that could otherwise travel to the well bore and be produced. One source of such residue is the gelling agent used in the fracturing fluid to create the viscosity necessary to suspend particulates in the fracturing fluid.
One method that has been employed to reduce the load of gelling agent in a fracturing fluid without affecting its ability to suspend proppant particulates has been to foam the fracturing fluid. For example, a gaseous internal phase may be mixed into a liquid fracturing fluid so that the liquid becomes an external phase to the gaseous internal phase. However, as the percentage of gas in the foam increases beyond a specific high quality limit, the ability of the foamed fracturing fluid to carry particulates is thought to decrease. Moreover, it may be difficult to maintain a competent foam with known foaming agents as the percentage of gas in the foam increases. While traditional foamed fracturing operations have a quality of between 50% and 75%, foams having qualities of 70% to 90% have been used in water sensitive formations. Moreover, it has long been believed that in order to successfully carry proppant particulates, a foamed fluid must have a fine, uniform texture rather than a coarse texture.
Another factor that may limit the universal application of a traditional fracturing fluid operation is that some formations are sensitive to the introduction of liquids commonly present in fracturing fluids (be it an aqueous liquid or an oil-based liquid). Thus, alternative operations have been developed wherein a fracturing fluid used is made up entirely of a gas, such as nitrogen or carbon dioxide. Even pure nitrogen treatments have been performed. Such operations eliminate the undesirable liquids, and may be particularly suited for use in shale and coal seam formations. Unfortunately, such 100% gas treatments are not suitable for delivering proppant particulates as part of the treatment.
While these alternative fracturing operations may show a benefit in increased production from a treated well bore, the benefits usually diminish as the fractured formation recovers and the fractures close. Generally, the benefit from such a job can be expected to last no more than 9 months. In order to get a more lasting benefit, it is necessary to have at least a portion of the fracturing fluid comprise a liquid so that the fluid may carry proppant particulates to the fractures. Thus, there is a tension between receiving more lasting benefit by including proppant and reducing the liquid load in the fracturing fluid when conducting fracturing operations in formations that are sensitive to the liquid components in a fracturing fluid.